Process for developing interwell communication in a tar sand

ABSTRACT

A hot, competent, permeable communications zone, connecting injection and production wells completed in a tar sand, is developed as follows: A cold, aqueous solution containing sodium hydroxide and a non-ionic surfactant is injected into a propped fracture system connecting the wells. The solution is circulated between the wells at a pressure below the fracture propping pressure. Bitumen is slowly emulsified in the solution and removed through the fracture system; a competent, bitumen depleted zone contiguous to the fracture zone is thereby developed. The temperature of the solution is then slowly increased and the quantities of sodium hydroxide and surfactant gradually decreased until pure steam only is being circulated.

United States Patent 1151 3,706,341 Redford 1 Dec. 19, 1972 54] PROCESSFOR DEVELOPING 2,910,123 10/1959 Elkins et al ..166/271 INTERWELLCOMMUNICATION IN A TAR SAND FOREIGN PATENTS OR APPLICATIONS Inventor:David Arthur Redford Fort 639,050 3/1962 Canada ..I66/272 Saskatchewan,Alberta, Canada 692,073 8/1964 Canada ..166/272 [73] Assignee: CanadianFina Oil Limited, Alberta, Primary Examiner-Stephen J. Novosad CanadaAttorney-Ernest Peter Johnson [22] F1led: Oct. 8, 1970 [57] ABSTRACT[21] Appl' 79346 A hot, competent, permeable communications zone, Iconnecting injection and production wells completed [52] U.S. Cl...166/275, 166/271, 166/272 in a tar sand, is developed as follows: Acold, aqueous [51] Int. Cl ..E21b 43/22, E2lb 43/24 solution containingsodium hydroxide and a non-ionic [58] Field of Search ..l66/266, 271,272, 274, 259, surfactant is injected into a propped fracture system166/261, 260, 257, 302, 303 connecting the wells. The solution iscirculated between the wells at a pressure below the fracture [56]References Cited propping pressure. Bitumen is slowly emulsified in thesolution and removed through the fracture system; a UNITED STATESPATENTS competent, bitumen depleted zone contiguous to 2 288 857 7/1942Subkow ..166/272 x the fracture thereby develpe The tempera- 2:882:9734/1959 Doscheretal. ..l66/266 We of the Solution is Slowly increased andthe 3,279,538 10/1966 Doscher ..166/271 quantities of sodium hydroxideand surfactant 3,379,250 4/1968 Matthews et al. ..l66/271 graduallydecreased until pure steam only is being cir- 3,396,79l 8/1968 Meurs etal 166/272 culated 3,490,532 1/1970 Carlin ..l66/272 X 3,500,913 3/1970Nordgren et al .166/27l X 4 Claims, No Drawings I PROCESS FOR DEVELOPINGINTERWELL COMMUNICATION IN A TAR SAND BACKGROUND OF THE INVENTIONThisinvention relates to a method for establishing a competent,permeable communication zone within a bitumen-containing sand bed. Whenformed, the zone connects injection and production wells-penetratinginto the bed. The zone is permeable to steam and is used to enableinjected steam to gain access to the bed across a wide area of contact.In this way, steam is used, in accordance with known processes, to heatand emulsify bitumen contained in the bed and render it mobile so thatit can be driven to and recovered from the production well.

' There are a number of known, bitumen-containing sand reservoirsscattered around the world. One of the largest of these is the depositlocated in the Athabasca region of Alberta, Canada. The presentinvention is discussed with reference to this particular deposit sincethe investigations leading up to the invention were carried out there.However, it will be appreciated that the process may find application inother deposits of the same type.

The Athabasca tar sand deposit has a lateralarea of several thousandsquare miles. The bitumen or oilbearing sandstone reservoir (referred tohereafter as the oil sand) is, in some areas of the deposit, exposed atground surface. These areas lend themselves to openpit type miningoperations the oil and sand are separated in a plant. The greatestpartof the deposit, however, is covered with overburden. This overburden canrange up to 1,000 feet in thickness. These portions of the depositcannot economically be mined by openpit methods. As a result,researchers in the field have worked toward developing in situ methodsfor recovering the oil.

The oil sand is mainly comprised of water-wet quartz grains. The oil orbitumen is located in the interstices between the water-sheathed grains.

The oil is extremely viscous at reservoir conditions. In fact it is abrittle solid having a viscosity of several million centipoises at 40F,the approximate reservoir temperature. It isself-evident that the oilcannot be pushed through the formation to a production well usingconventional means, such as a pressure gradient.

Workers have long been investigating ways and means for economicallyunlocking the subterranean tar sands so as to recover the contained oil.Generally speaking, these investigations have been concerned withconverting the oil to a less viscous state so that it can be driven toand recovered from production wells using conventional pumping or gaslift means.

One such procedure which is particularly promising involvesspontaneously emulsifying the oil to form an oil-in-water emulsion. Theproduct emulsion has a viscosity approaching that of water. Thisprocedure is described in the following patents: US. Pat. Nos.2,882,973, 3,221,813, 3,279,538, 3,379,250 and 3,396,791; and CanadianPat. No. 639,050. I

From these patents, the following teachings are known:

Canadian Pat. No. 639,050 discloses the composition of a solution which,when injected into a tar sand, spontaneously emulsifies contained oil.The solution comprises water containing between 0.001 and 1.0 percent byweight of sodium hydroxide. According to U.S. Pat. No. 2,882,973, theemulsifying power of the caustic solution described in Canadian Pat. No,639,050 is improved by admixing with it a non-ionic surfactant, such asan oil-soluble monohydric alcohol. The surfactant is provided in anamount between 0.1 and 5 percent by weight.

The prior art also teaches drilling production an injection wells intothe formation, fracturing the tar sand horizontally to establishcommunications between the wells and then pumping steam through thefracture system. The steam moves upwardly from the fracture into thesand reservoir. In so doing, it heats the cold oil while the steamcondenses. The heated oil and water combine to form an oil-in-wateremulsion. This emulsion accumulates in the fracture and is forced to theproduction well by the pressure of the injected steam.

One problem with this system is that the emulsion cools as it moves awayfrom the hot zone surrounding the injection well. As it cools, the oilagain solidifies to form an impermeable block in the fracture system.The

' injection pressure then rises and undesirable vertical fracturing canoccur.

Another problem is that the tar sand softens as it is heated toemulsifying temperatures; the formation then tends to slump into thefracture, thereby blocking it.

To overcome these problems, US. Pat. No. 3,221,813 teaches a procedurewherein steam is injected into the fracture at a pressure above thetheoretical fracture propping pressure (about 0.7 psi. per foot ofoverburden) but below the theoretical formation fracturing pressure.This apparently avoids the problems which arise from slumping. Ifblockage of the fracture system occurs, caustic solution is injectedinto the fractures to clean out the block. Steam injection is then againresumed.

While the procedure taught in patent 3221813 has application in areashaving a thick overburden, it is not feasible in those areas where theoverburden is thin, as in the order of 200-300 feet. Here the fracturingand propping pressures are so close to each other that verticalfracturing easily occurs if one attempts to operate at the proppingpressure. This, of course, leads to blowouts or migration of the steaminto thief zones.

SUMMARY OF THE INVENTION The present invention is based on theproposition that it is desirable, before introducing steam to the formation, to create a hot, competent, permeable, depleted sand zonecontiguous to the fracture zone and extending between the wells. By hot"is meant that the temperature within the two zones is sufficient tocause reservoir oil to combine with water to form a mobile emulsion. Theavailability of this continuous hot zone within the tar sand formationmeans that solidification by cooling of emulsified bitumen movingthrough the fractures does not occur to any substantial extent. Slumpingof the formation is not a problem as the high temperature of thefracture and depleted sand zones ensures rapid emulsification of thebitumen; the slumping bitumen is therefore removed, leaving competentclean sand.

Now, this is not a novel proposition. It has, for example, beensuggested in 11.8. Pat. No. 3,396,791. However, the prior art has onlyused techniques involving "um I nlnn high pressure and temperature toform the hot zone. Such processes are not suitable for use in tar sandareas where the overburden is thin.

It is an object of this invention to provide a low pressure processwhich can be used to develop a zone of 5 communication between injectionand production wells.

' It is another object of this invention to provide a low pressureprocess for establishing a zone, permeable to steam, which extendsthrough a tar sand formation and connects two wells which penetrate thesand, said zone being competent and having a temperature at which thereservoir oil will combine readily with water in the zone to form amobile emulsion.

It is another object to provide a cheap, effective agent which isadapted to react with bitumen to render part of it soluble in water andincrease its susceptibility to emulsification.

I have found that the emulsifying sodium hydroxide solutions of theprior art do not emulsify bitumen at temperatures up to about 60F;additionally, they have slow emulsifying effect at temperatures betweenabout 60 and 90F. It is not until the solutions are at temperaturesabove about 90F that they become emulsifying agents of any practicalvalue. I have also found that the bitumen or oil in tar sand is brittleat 40-60F, begins to soften (so that it can slump) at about 60-90 Fandbegins to form mobile, viscous fluid at temperatures above 90F. Asheating is continued, more of the bitumen becomes fluid and theviscosity of the fluid lessens. Finally, I have found that a non-ionicsurfactant, of the type described in US. Pat. No. 2,882,973, togetherwith critical concentrations of sodium hydroxide slowly but effectivelyemulsifies bitumenv at temperatures between 40 and 90F. The emulsifyingpower of this solution increases with temperature. Havring made theseobservations, I have developed the series of steps which comprises theinvention.

. For purposes of this disclosure, a cold solution is one whosetemperature, when injected into the tar sand formation, is about thesame as the formation temperature.

In accordance with the first stage of the invention, a cold agent ispumped through the fracture zone to emulsify and remove bitumen attemperatures below 90F. The agent is capable of emulsifying and/ordissolving bitumen at temperatures between 40 and 90F. One preferredagent is an aqueous solution containing sodium hydroxide and a non-ionicsurfactant. Another preferred agent is ozone.

The agent is injected into the fracture zone at a bottom hole'pumpingpressure which is kept substantially below the fracture proppingpressure. It is circulated between the wells for a period of time at lowpressure so as to gradually emulsify and/or dissolve bitumen ad.-joining the fracture zone. In this manner a competent, bitumen-depletedzone contiguous to the fracture zone is developed. The fracture zone andcontiguous depleted zone combine to provide a permeable communicationzone connecting the wells.

Afterinitial interwell communication has been developed using a coldsolution containing sodium hydroxide and non-ionic surfactant, theinjection temperature of the solution is slowly increased. It will beappreciated that, as the temperature of the injected solution is raised,the bitumen becomes mobile in increasing quantities; simultaneously, theemulsifying power of the solution is increased. The rate of injectionand the composition and temperature of the solution are thereforecontrolled to achieve two objects:

a. removal from the formation of the bitumen which is emulsified; and

b. the maintenance of a bottom hole injection pressure which issubstantially less than the fracture propping pressure.

After the injection temperature of the solution reaches about F, one canbegin to decrease the nonionic surfactant content while simultaneouslycontinuing to slowly raise the solution temperature and pumping rate.This is continued until the surfactant is eliminated from the solution.At about F, one can also begin to gradually reduce the sodium hydroxidecontent of the solution. This is continued until the sodium hydroxidehas been eliminated from the solution. Both the surfactant and thesodium hydroxide may be eliminated from the solution by the time itstemperature is raised to 200F.

It is found at this stage that the communication zone connecting thewells is sufficiently permeable to allow steam to be injected thereintoat desirable rates at pressures below the fracture propping pressure.

In the case where ozone has been used to develop the initialcommunication zone, an aqueous solution containing emulsifying compoundscan be introduced to the zone and circulated at gradually increasingtemperature, as just described.

DESCRIPTION OF THE PREFERRED EMBODIMENT Geology and Completion:

The vertical geology of the Athabasca tar sand for mation varies atdifferent locations. In some areas, the oil-saturated zone is feet thickwith relatively few clay stringers or permeable water-saturated zones.In other areas, the formation may only be 35 feet thick and crowded withclay and water-saturated lenses. In some areas, the pay zone is cappedwith a thick, impermeable shale bed;.in others, it is not.

The selection of a suitable area for carrying on an in situ oil recoveryprogramme is important to its success. Ideally, the vertical section ofthe well should have a reasonably thick overburden and an impermeablecap rock over the pay zone. The overburden and cap rock thicknessespreferably are at least 100 feet each. The fewer the potential thiefzones within the bed, the better.

I prefer to complete both the injection and production wells by drillingeach well to the base of the tar sands and casing off all but the bottom5-10 feet. By fracturing the formation at its base, a vertical steamsweep of the entire pay zone is a possibility; by easing off thepotential thief zones the probability of directing the emulsifyingfluids into the desirable regions of the reservoir is increased.

Well Spacing:

Spacing is controlled to a large extent by the thickness of theoverburden. The thicker it is, the higher will be the pressures whichcan be used during fracturing without incurring blow-outs or excessivevertical fracturing.

'1 space the wells apart by about l-foot of spacing for each pound ofinjection pressure which is applied. In other words, if one injects at100 p.s.i., the two wells can be spaced about 100 feet apart.

Fracturing: Y

At the present time, hydraulic fracturing with a propping agentsprovides the best means for establishing initial interwellcommunication. Conventional techniques are used. To illustrate, I obtaincommunication between two wells 100 feet apart by breaking down theformation using cold water and then injecting water, carrying b lb/gal.of 20-40 mesh sand, into one well at a rate of about 180 bbl/hr untilsandreturns are obtained at the second well.

Completion:

it is desirable to provide means for excluding sand in the productionwell after fracturing. I use conventional slotted liners packed with8-12 mesh sand.

Fluid Lifting:

Experience has shown that bottom hole pumps are inadequate for bringingthe emulsion to surface through the production well. The produced sandand silt soon leaves the pump inoperative, even with a liner present.However, good results can be obtained using conventional air liftprocedures.

Communications development:

Once communication has been achieved through a fracture system at thebaseof the tar sand, it is necessary to'develop the system into a usableflow path which will accept large volumes of steam without sealing off.This is initiated by causing cold emulsification of the bitumen to occurwithin or immediately adjacent to the fracture path.

Cold emulsification is carried out by injecting an aqueous solution ofsodium hydroxide and non-ionic surfactant into the fracture system. Thesodium hydroxide is provided in an amount less than 1.0 percent byweight; the non-ionic surfactant is provided in an amount within therange 0.1 to 5 percent by weight.

It is found that caustic does not emulsify bitumen below about 56F. Atabout 79F, bitumen is emulsified on prolonged contact (18 hours or more)with solutions containing 0.10 to 0.20 percent by weight of caustic. At90-100F, emulsions readily form when using solutions containing 0.05percent caustic but take at least 3 hours to form when using solutionscontaining 0.10 percent. From the foregoing it will be noted that theeffective bitumen emulsification power of caustic begins at about 90Fand increases with temperature. it will also be noted that the optimumconcentration for emulsion formation shifts to lower values as thetemperature is increased.

With reference to the non-ionic surfactant, it is preferable to use anoctylphenoxypolyethyleneoxy ethanolwherein the side chain of the benzenering is branched and wherein there are 5 polyethylene groups. Thiscompound is sold by Rohm and Haas under the designation Triton X-45. Thequantity used is preferably within the range 0.4 to 0.1 percent byweight.

The optimum concentrations of these agents, relative to temperature, arein the order of the following:

TABLE 1 TX45 concentration (5) NaOH concentra- The solution is pumped atlow pressure throughout the period of developing the communication zone.For example, 1 try to keep the wellhead injection pressure for a 230foot deep well below p.s.i. When working with deeper wells which have athicker overburden, one can use higher injection pressures.

The following example further illustrates the invention:

EXAMPLE 1 Three wells, A,B and C were drilled into the Athabasca tarsand at 50 foot intervals along a line. The injection well A wasbottomed in limestone at 223 feet.

; It was cased to 212 feet. The temperature survey well B was bottomedin limestone at 225 feet and cased to total depth. It was perforated inthe tar sand at 223 feet. The production well C was bottomed inlimestone at 230 feet and cased to 209 feet.

The tar sand, about 60 feet thick, immediately overlaid the limestone.The formation was, in turn, overlain with glacial till. There was noimpermeable cap rock, such as a shale bed, above the tar sand.

The tar sand was hydraulically fractured through the temperature well B.The formation was broken down using water at 550-200 p.s.i.g. Watercarrying lb/gal.

of 20-40 mesh round sand was fed to the formation at 3 bbls/min. untilsand returns were observed at wells A and C.

The production well was then completed with a gravel pack.

Following completion, injection down well A was begun. The solution usedcontained 0.4% by weight Triton X-45 and 0.2 percent by weight caustic.It had an injection temperature of 40F. The solution wasfed to theformation at 2-4 bbls/hour for 8 days at less than 25 p.s.i.g. Returnsof "i4 bbl/hour were observed at the production well C 6 hours afterlifting began. After 3 days, the returns comprised an emulsioncontaining 1.5 percent by weight bitumen. These conditions remainedconstant throughout this injection period. The returns were removed fromthe production well using an air lift. Injection through well A wasstopped for 6 weeks.

After this period, injection was resumed through temperature well 8.Production was recovered through both the injection and production wellsA and C. The well head temperature of the solution was increased from astarting temperature of 50F to a final temperature of 200F over a periodof days at a rate of approximately 10F every 2 days. During this period,the wellhead pressure rose from 50 to 140 p.s.i.g. and then dropped to asteady level of 50-100 p.s.i.g. at an injection rate of 4-5 bbls/hour.The composition of the solution was varied as follows:

Production commenced through well C at 2 bbl/hour, declined after a weekto /4 bbl/hour, remained at that level for 3 weeks and then increased to3-4 bbls/hour for the last week. The product contained 1-2 percent byweight bitumen during the first 3 weeks; this content rose to 7-10percent by weight during the final week.

'The final wellhead injection temperature was about 200F and the finalproduction temperature about 140F.

Low quality steam was then injected through well A at temperatures up to350F and bitumen emulsion produced at well C at temperatures up to 280F.

EXAMPLE II This example illustrates the use of ozone as a means forestablishing a bitumen-depleted zone within the tar sand.

A 1 k X 18 inch glass tube was packed with 800 grams of Athabasca tarsand. Oxygen containing 6-7 percent by volume ozone was passed throughthe tube for 2 days at 170 millimeters per minute. The experiment wascarried out at room temperature.

During this period, the color of the sample changed from black to grayas many white, clean sand grains appeared.

At the end of the period, water was passed through the tube. Thecollected solution was dark brown in color and foamed when shakenlightly. It was evaporated to dryness and the solid product analyzed asfollows:

TABLE III Constituent by weight carbon hydrogen oxygen nitrogen sulphurdrying loss A portion of the remaining tar sand was .divided into three50 gram parts A, B and C. These parts were each placed in a tube.

Part A was saturated at 40F with water containing 0.2 percent by weightsodium hydroxide and 0.4 percent by weight Triton X-45. Within 30minutes the solution turned dark brown, indicating very rapidemulsification.

Part B was saturated at 40F with water containing 0.2 percent by weightsodium hydroxide. No change in the color of the solution had occurredafter 2 days.

' Part C was saturated at 40F with water containing .4% by weight TritonX-45. Some darkening of this solution occurred in 30 minutes.

A fourth partD of the ozonized tar sand was stirred with water at roomtemperature under a microscope. The sand grains became water wet andbitumen separated to form globules in the water phase. When non-ozonizedtar sand was subjected to the same test, nothing happened.

.From these results it will be noted that:

a. treatment of tar sand with ozone converts some bitumen to awater-soluble form;

b. some of the ozonized bitumen has surface active characteristics; and

c. ozonized tar sand is more amenable to spontaneous emulsification withan aqueous solution of sodium hydroxide and non-ionic surfactant than isotherwise the case.

EXAMPLE III This example illustrates that ozone is effective atformation temperature.

A horizontal 3 foot X 2 inch column was tightly packed with 5.2 poundsof Athabasca tar sand. A Va inch diameter path of 20-40 mesh round sandwas incorporated in the tar sand along the bottom of the column.

Oxygen containing 5-6 percent by volume ozone'was passed through thecolumn for 61 hours. The exit gas contained only 1 percent ozone.

A 50 gram sample of the ozonized tar-sand was extracted in 500milliliters of water. The product solution was dark brown in color andfoamed when shaken slightly. The solution was evaporated to dryness and0.237 grams of solid collected. This solid analyzed as A second 50'gramsample was extracted with 1.1 liters of water. The solution required41.4 cubic centimeters of 0.1 sodium hydroxide to neutralize it. Thistest indicated the formation of acid groups due to reaction between theozone and bitumen.

What is claimed is:

l. A method for establishing a hot, permeable communication zone in abitumen-containing sand forma-.

tion extending between production and injection wells, said formationhaving a propped fracture zone extending between the wells, whichcomprises:

pumping a solution, having a temperature substantially the same as theformation temperature, into the fracture zone, said solution beingcapable of emulsifying bitumen at temperatures between 40 and F; forcingthe solution from the injection well to the production well by pumpingit through the fracture zone at a bottom hole pumping pressure which issubstantially less than the fracture propping pressure; contuing to pumpthe solution, while simultaneously gradually increasing its temperature,through the formation at .a bottom hole pumping pressure which issubstantially less than i the fracture between 0.1 and 5 percent byweight.

3. The method as set forth in claim 2 wherein:

the non-ionic surfactant is octylphenoxypolyethyleneoxy ethanol and itis provided in the solution in an amount less than 0.4% by weight.

4. The method as set forth in claim 2 wherein:

the non-ionic surfactant content of the solution is gradually decreasedafter the injection temperature of the solution rises above about F.

2. The method as set forth in claim 1 wherein: the solution compriseswater containing sodium hydroxide in an amount less than 1.0 percent byweight, and a non-ionic surfactant in an amount between 0.1 and 5percent by weight.
 3. The method as set forth in claim 2 wherein: thenon-ionic surfactant is octylphenoxypolyethyleneoxy ethanol and it isprovided in the solution in an amount less than 0.4% by weight.
 4. Themethod as set forth in claim 2 wherein: the non-ionic surfactant contentof the solution is gradually decreased after the injection temperatureof the solution rises above about 60*F.